**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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**FORM 10-Q**

**x**                              QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934 for the quarterly period ended March 31, 2006

**or**

**o**                                 TransitionReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934 for the transition period from              to              

**CommissionFile Number: 0-6910**

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**TEL OFFSHORE TRUST**

(Exact Name of Registrant as Specified in its Charter)

| **Texas**                                 | **76-6004064**       |
|-------------------------------------------|----------------------|
| (State or other  jurisdiction of          | I.R.S. Employer      |
| Incorporation, or  Organization)          | Identification  No.) |
| **JPMorgan Chase Bank, N.A.**             | ** **           |
| **Worldwide  Security Services**          | ** **           |
| **700  Lavaca Street**                    | ** **           |
| **Austin,  Texas**                        | **78701**            |
| (Address of  Principal Executive Offices) | (Zip Code)           |

 

Registrant’s Telephone Number, Including Area Code: **(800) 852-1422**

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days.  Yes x    No o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer or anon-accelerated filer. See definition of “accelerated filer or largeaccelerated filer” in Rule 12b-2 of the Exchange Act 

**(Check one):**Large AcceleratedFiler o  Accelerated Filer o  Non-acceleratedfiler x

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2of the Act). Yes o   No x

Indicate the number ofshares outstanding of each of the registrant’s classes of common stock, as ofthe latest practicable date. As of May 15, 2006—4,751,510 Units ofBeneficial Interest in TEL Offshore Trust.

 

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**NOTE REGARDINGFORWARD-LOOKING STATEMENTS**

This Form 10-Q includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-Q are forward-looking statements. Although theWorking Interest Owners (as defined herein) have advised the Trust that theybelieve that the expectations reflected in the forward-looking statementscontained herein are reasonable, no assurance can be given that suchexpectations will prove to have been correct. Important factors that couldcause actual results to differ materially from expectations (“CautionaryStatements”) are disclosed in this Form 10-Q, including, withoutlimitation, in conjunction with the forward-looking statements includedin this Form 10-Q. A summary of certain principal risks andCautionary Statements is also included in the Trust’s most recent Form 10-Kunder Item 1A “Risk Factors.” All subsequent written and oral forward-lookingstatements attributable to the Trust or persons acting on its behalf areexpressly qualified in their entirety by the Cautionary Statements.

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        FinancialStatements.

**TEL OFFSHORE TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**

| ** **                                                                                                                                | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                                                                                                                | ** ** | **2006**           | ** ** | **2005**              | ** ** |
| **Assets**                                                                                                                                | ** ** | ** **         | ** ** |                  | ** ** | ** ** |   |
| Cash and cash  equivalents                                                                                                                |       | $                  | 1,199,813  |                  |       | $ | 3,175,221 | ** ** |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,206,075 and $28,203,586, respectively |       | 61,580             |       |                  | 64,069     | ** ** |   |
| Total assets                                                                                                                              |       | $                  | 1,261,393  |                  |       | $ | 3,239,290 | ** ** |   |
| **Liabilities  and Trust Corpus**                                                                                                         | ** ** | ** **         | ** ** |                  | ** ** | ** ** |   |
| Distribution  payable to Unit holders                                                                                                     |       | $                  | —     |                  |       | $ | 1,811,018 | ** ** |   |
| Reserve for  future Trust expenses                                                                                                        |       | 1,199,813          |       |                  | 1,364,203  | ** ** |   |
| Commitments and  contingencies                                                                                                            |       |               |       |                  |       | ** ** |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized   and outstanding)                                                       |       | 61,580             |       |                  | 64,069     | ** ** |   |
| Total liabilities and  Trust corpus                                                                                                       |       | $                  | 1,261,393  |                  |       | $ | 3,239,290 | ** ** |   |

 

**STATEMENTS OF DISTRIBUTABLE INCOME(Unaudited)**

| ** **                                                | ** ** | **Three Months Ended** | ** ** |
|-----------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                | ** ** | **March 31,**               | ** ** |
| ** **                                                | ** ** | **2006**                         | ** ** | **2005** | ** ** |
| Royalty income                                            |       | $                                | —     |   | $ | 526,972 |   |
| Interest income                                           |       | 4,792                            |       | 2,821 |   |
|                                                      |       | 4,792                            |       | 529,793 |   |
| Decrease/(Increase)  in reserve for future Trust expenses |       | 164,390                          |       | (68,906 | ) |
| General and  administrative expenses                      |       | (169,182                         | )          | (144,452 | ) |
| Distributable  income                                     |       | $                                | —     |   | $ | 316,435 |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                | .000000    |   | $ | .066597 |   |

 

The accompanying notes are an integral part of these financial statements.

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**STATEMENTS OF CHANGES IN TRUST CORPUS(Unaudited)**

| ** **                                       | ** ** | **Three Months Ended** | ** ** |
|--------------------------------------------------|------------|----------------------------------|------------|
| ** **                                       | ** ** | **March 31,**               | ** ** |
| ** **                                       | ** ** | **2006**                         | ** ** | **2005** | ** ** |
| Trust corpus,  beginning of period               |       | $                                | 64,069     |   | $ | 90,053 |   |
| Distributable  income                            |       | —                           |       | 316,435 |   |
| Distribution  payable to Unit holders            |       | —                           |       | (316,435 | ) |
| Amortization of  net overriding royalty interest |       | (2,489                           | )          | (2,601 | ) |
| Trust corpus, end of  period                     |       | $                                | 61,580     |   | $ | 87,452 |   |

 

The accompanying notes are an integral part of these financial statements.

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**Note 1—TrustOrganization**

Tenneco Offshore Company, Inc. (“Tenneco Offshore”)created the TEL Offshore Trust (“Trust”) effective January 1, 1983,pursuant to the Plan of Dissolution (“Plan”) approved by Tenneco Offshore’sstockholders on December 22, 1982. In accordance with the Plan, the TELOffshore Trust Partnership (“Partnership”) was formed in which the Trust owns a99.99% interest and Tenneco Oil Company (“Tenneco”) initially owned a .01%interest. In general, the Plan was effected by transferring an overridingroyalty interest (“Royalty”) equivalent to a 25% net profits interest in theoil and gas properties (the “Royalty Properties”) of TennecoExploration, Ltd. (“Exploration I”) located offshore Louisiana to thePartnership and issuing certificates evidencing units of beneficial interest inthe Trust (“Units”) in liquidation and cancellation of Tenneco Offshore’scommon stock.

On October 31, 1986, Exploration I was dissolvedand the oil and gas properties of Exploration I were distributed toTenneco subject to the Royalty. Tenneco, who was then serving as the ManagingGeneral Partner of the Partnership, assumed the obligations of Exploration I,including its obligations under the instrument conveying the Royalty to thePartnership (the “Conveyance”). The dissolution of Exploration I had noimpact on future cash distributions to holders of units of beneficial interest.

On November 18, 1988, Chevron U.S.A., Inc. (“Chevron”)acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco,including all of the Royalty Properties. As a result of the acquisition,Chevron replaced Tenneco as the Working Interest Owner and Managing GeneralPartner of the Partnership. Chevron also assumed Tenneco’s obligations underthe Conveyance.

On October 30, 1992, PennzEnergy Company (“PennzEnergy”)(which merged with and into Devon Energy Production Company L.P. effective January 1,2000) acquired certain oil and gas producing properties from Chevron, includingfour of the Royalty Properties. The four Royalty Properties acquired byPennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 andEugene Island 208. As a result of such acquisition, PennzEnergy replacedChevron as the Working Interest Owner of such properties on October 30,1992. PennzEnergy also assumed Chevron’s obligations under the Conveyance withrespect to these properties.

On December 1, 1994, Texaco Exploration andProduction Inc. (“TEPI”) acquired two of the Royalty Properties fromChevron. The Royalty Properties acquired by Texaco were West Cameron 643 andEast Cameron 371/381. As a result of such acquisitions, TEPI replaced Chevronas the Working Interest Owner of such properties on December 1, 1994. TEPIalso assumed Chevron’s obligations under the Conveyance with respect to theseproperties.

On October 1, 1995, SONAT Exploration Company (“SONAT”)acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1,1995, Amoco Production Company (“Amoco”) acquired the Eugene Island 367property from PennzEnergy. As a result of such acquisitions, SONAT and Amocoreplaced PennzEnergy as the Working Interest Owners of the East Cameron 354 andEugene Island 367 properties, respectively, on October 1, 1995 andalso assumed PennzEnergy’s obligations under the Conveyance with respect tothese properties.

Effective January 1, 1998, Energy ResourceTechnology, Inc. (“ERT”) acquired the East Cameron 354 property fromSONAT. As a result of such acquisition, ERT replaced SONAT as the WorkingInterest Owner of the East Cameron 354 property effective January 1, 1998,and also assumed SONAT’s 

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obligations under theConveyance with respect to such property. In October 1998, Amerada HessCorporation (“Amerada”) acquired the East Cameron 354 property from ERTeffective January 1, 1998. As a result of such acquisition, Ameradareplaced ERT as the Working Interest Owner of the East Cameron 354 propertyeffective January 1, 1998, and also assumed ERT’s obligations under theConveyance with respect to this property.

Effective January 1, 2000 PennzEnergy and DevonEnergy Corporation (Nevada) merged into Devon Energy Production Company L.P. (“Devon”).As a result of such merger, Devon replaced PennzEnergy as the Working InterestOwner of Eugene Island 348 and Eugene Island 208 properties effective January 1,2000, and also assumed PennzEnergy’s obligations under the Conveyance withrespect to these properties.

On October 9, 2001, a wholly owned subsidiary ofChevron Corporation, a Delaware corporation, merged (the “Merger”) with andinto Texaco Inc., a Delaware corporation (“Texaco”), pursuant to anAgreement and Plan of Merger, dated as of October 15, 2000. As a result ofthe Merger, Texaco Inc. became a wholly owned subsidiary of ChevronCorporation, and Chevron Corporation changed its name to “ChevronTexacoCorporation” in connection with the Merger. Effective May 9, 2005,ChevronTexaco Corporation changed its name to Chevron Corporation. Accordingly,the properties referred to herein by Chevron and Texaco are each now controlledby subsidiaries of Chevron Corporation.

On May 1, 2002, TEPI assigned all of itsinterests in West Cameron 643 and East Cameron 371/381 to Chevron. Accordingly,pursuant to the Conveyance of the Royalty Properties, net profits interest willbe calculated for the collective Royalty Properties owned by Chevron after thisdate.

On June 6, 2003 Anadarko Petroleum Corporation (“Anadarko”)acquired, among other interests, a 25% Working Interest in the East Cameron 354field subject to a 25% Net Profit Interest property from Amerada effective April 1,2003. As a result of this transaction, Anadarko replaced Amerada as the WorkingInterest Owner of East Cameron 354 effective July 1, 2003 and also assumedAmerada’s obligations under the conveyance with respect to said property.

Effective October 1, 2004, Apache acquiredAnadarko’s interest in East Cameron 354 and assumed Anadarko’s obligationsunder the conveyance with respect to this property.

All of the Royalty Properties continue to be subjectto the Royalty, and it is anticipated that the Trust and the Partnership, ingeneral, will continue to operate as if the above-described sales of theRoyalty Properties had not occurred.

Unless the context inwhich such terms are used indicates otherwise, in these Notes to Financial Statementsthe terms “Working Interest Owner” and “Working Interest Owners” generallyrefer to the owner or owners of the Royalty Properties (TennecoExploration, Ltd. through October 31, 1986; Tenneco for periods from October 31,1986 until November 18, 1988; Chevron with respect to all RoyaltyProperties for periods from November 18, 1988 until October 30, 1992,and with respect to all Royalty Properties except East Cameron 354, EugeneIsland 348, Eugene Island 367 and Eugene Island 208 for periods from October 30,1992 until December 1, 1994, and with respect to the same propertiesexcept West Cameron 643 thereafter; PennzEnergy/Devon with respect to EastCameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208for periods from October 30, 1992 until October 1, 1995, and withrespect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI withrespect to West Cameron 643 and East Cameron 371/381 for periods beginning onor after December 1, 1994 until May 1, 

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2002;SONAT with respect to East Cameron 354 for periods beginning on or after October 1,1995; and Amoco with respect to Eugene Island 367 for periods beginning on orafter October 1, 1995; Amerada with respect to East Cameron 354 forperiods beginning on or after January 1, 1998; Chevron with respect toWest Cameron 643 and East Cameron 371/381 on and after May 1, 2002; andAnadarko with respect to East Cameron 354 on and after July 1, 2003 until October 1,2004; and Apache with respect to East Cameron 354 after October 1, 2004).

**Note 2—Basisof Accounting**

The accompanying unaudited financial information hasbeen prepared by JPMorgan Chase Bank, N.A. (“Corporate Trustee”) inaccordance with the instructions to Form 10-Q and does not includeall of the information required by accounting principles generally accepted inthe United States of America for complete financial statements, although theCorporate Trustee and the individual trustees (collectively, the “Trustees”)believe that the disclosures are adequate to make the information presented notmisleading. The information furnished reflects all adjustments which are, inthe opinion of the Trustees, necessary for a fair presentation of the resultsfor the interim periods presented. The financial information should be read inconjunction with the financial statements and notes thereto included in theTrust’s Annual Report on Form 10-K for the year ended December 31,2005.

The financial statements of the Trust are prepared onthe following basis:

(a)          Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter. In addition, Royalty incomeincludes amounts related to funds deposited or released from the Special CostEscrow account—see (c); and

(b)         Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses; and

(c)          The funds deposited orreleased from the Special Cost Escrow account are recorded at the time ofpayment or receipt. The Special Cost Escrow account is an account of theWorking Interest Owners and is not reflected in the financial statements of theTrust.

This manner of reporting income and expenses isconsidered to be the most meaningful because the quarterly distributions toUnit holders are based on net cash receipts received from the Working InterestOwners. The financial statements of the Trust differ from financial statementsprepared in accordance with generally accepted accounting principles, because,under such principles, Royalty income and Trust general and administrativeexpenses for a quarter would be recognized on an accrual basis. In addition,amortization of the net overriding royalty interest, which is calculated on aunits-of-production basis, is charged directly to Trust corpus since suchamount does not affect distributable income.

Cash and cash equivalents include all highly liquid,short-term investments with original maturities of three months or less.

The changes in reserve for future Trust expensesincludes both changes of amounts deemed necessary by the Trustees and relateddistributions, as well as amounts paid from the reserve during periods when theTrust has insufficient income to pay Trust expenses.

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The Trust reviews the net overriding royalty interestin oil and gas properties for possible impairment whenever events orcircumstances indicate the carrying amount of the asset may not be recoverable.If there is an indication of impairment, the Trust prepares an estimate offuture cash flows (undiscounted and without interest charges) expected toresult from the use of the asset and its eventual disposition. If these cashflows are less than the carrying amount of the asset, an impairment loss isrecognized to write down the asset to its estimated fair value. Preparation ofestimated expected future cash flows is inherently subjective and is based onthe Corporate Trustee’s best estimate of assumptions concerning expected futureconditions. There were no write downs taken in the periods presented.

The Special Cost Escrow account (Note 5) isestablished for the future costs to be incurred to plug and abandon wells,dismantle and remove platforms, pipelines and other production facilites andfor the estimated amount of future capital expenditures on the RoyaltyProperties. The funds held in the Special Cost Escrow account are not reflectedin the financial statements of the Trust. However, funds deposited to orreleased from the Special Cost Escrow account are included in Royalty income.

The preparation of financial statements requires theTrustees to make use of estimates and assumptions that affect amounts reportedin the financial statements as well as certain discounts. Actual results coulddiffer from those estimates.

The amount of cashdistributions by the Trust is dependent on, among other things, the salesprices for oil and gas produced from the Royalty Properties and the quantitiesof oil and gas sold. It should be noted that substantial uncertainties existwith regard to future oil and gas prices, which are subject to materialfluctuations due to changes in production levels and pricing and other actionstaken by major petroleum producing nations, as well as the regional supply anddemand for gas, weather, industrial growth, conservation measures, competitionand other variables. The Trust does not enter into any hedging transactions onfuture production.

**Note 3—NetOverriding Royalty Interest**

The Royalty entitles theTrust to its share (99.99%) of 25% of the Net Proceeds attributable to theRoyalty Properties. The Conveyance, dated January 1, 1983, provides thatthe Working Interest Owners will calculate, for each period of three monthscommencing the first day of February, May, August and November, an amountequal to 25% of the Net Proceeds from their oil and gas properties for theperiod. Generally, “Net Proceeds” means the amounts received by the WorkingInterest Owners from the sale of minerals from the Royalty Properties lessoperating and capital costs incurred, management fees and expensereimbursements owing to the Managing General Partner of the Partnership,applicable taxes other than income taxes, and a Special Cost Escrow account.The Special Cost Escrow account (See Note 5) is established for the futurecosts to be incurred to plug and abandon wells, dismantle and remove platforms,pipelines and other production facilities, and for the estimated amount offuture capital expenditures on the Royalty Properties. Net Proceeds do notinclude amounts received by the Working Interest Owners as advance gaspayments, “take-or-pay” payments or similar payments unless and until suchpayments are extinguished or repaid through the future delivery of gas.

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**Note 4—Distributionsto Unit Holders**

In accordance with the provisions of the TrustAgreement, generally all Net Proceeds received by the Trust, net of Trustgeneral and administrative expenses and any cash reserves established for thepayment of contingent or future obligations of the Trust, are distributedcurrently to the Unit holders. Such distributions are referred to as “distributableincome.” The amounts distributed are determined on a quarterly basis and arepayable to Unit holders of record as of the last business day of each calendarquarter. However, cash distributions are made in January, April, July and October andinclude interest earned from the quarterly record date to the date ofdistribution.

Gulf Coast hurricanes caused significant damage during2005. Even if platforms and facilities on the Royalty Properties are restoredin a timely manner during 2006, delays in repairs on third-party transportationsystems may continue to limit production and Royalty income from the RoyaltyProperties.

**Note 5—Special CostEscrow Account**

The Special Cost Escrow is an account of the WorkingInterest Owners, and it is described herein for informational purposes only.The Conveyance provides for the reserve of funds for estimated future “SpecialCosts” of plugging and abandoning wells, dismantling platforms and other costsof abandoning the Royalty Properties, as well as for the estimated amount offuture drilling projects and other capital expenditures on the RoyaltyProperties. As provided in the Conveyance, the amount of funds to be reservedis determined based on certain factors, including estimates of aggregate futureproduction costs, aggregate future Special Costs, aggregate future net revenuesand actual current net profits interest. Deposits into this account reducecurrent distributions and are placed in an escrow account and invested inshort-term certificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts. Special Cost Escrow funds will generally be utilized to pay SpecialCosts to the extent there are not adequate current net profits interest to paysuch costs. Special Costs that have been paid are no longer included in theSpecial Cost Escrow calculation. Deposits to the Special Cost Escrow accountwill generally be made when the balance in the Special Cost Escrow account isless than 125% of estimated future Special Costs and there is a Net RevenuesShortfall (a calculation of the excess of estimated future costs over estimatedfuture net revenues pursuant to a formula contained in the Conveyance). Whenthere is not a Net Revenues Shortfall, amounts in the Special Cost Escrowaccount will generally be released, to the extent that Special Costs have beenincurred. Amounts in the Special Cost Escrow account generally will also bereleased when the balance in such account exceeds 125% of estimated futureSpecial Costs. In the first quarter of 2006, there was a net deposit of fundsto the Special Cost Escrow account of $876,000. In the first quarter of 2005,there was a net deposit of funds to the Special Cost Escrow account of$1,944,000. As of March 31, 2006, $6,492,125 remained in the Special CostEscrow account. The funds held in the Special Cost Escrow account are notreflected in the financial statements of the Trust.

Chevron, in its capacityas Managing General Partner of the Partnership, has advised the Trust thatadditional deposits to the Special Cost Escrow account may be required infuture periods in connection with other production costs, other abandonmentcosts, other capital expenditures and changes in the estimates and factorsdescribed above. Such deposits could result in a significant reduction inRoyalty 

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incomein the periods in which such deposits are made, including the possibility thatno Royalty income would be received in such periods.

**Note 6—ReserveFor Future Trust Expenses**

The Trust made a determination in 1998 to maintain acash reserve equal to three times the average expenses of the Trust during eachof the past three years to provide for future administrative expenses inconnection with the winding up of the Trust. The reserve amount for 2006 wascalculated to be $1,504,904. During the first quarter of 2006, the Trust used$164,390 from the Trust’s cash reserve account to pay the Trust’s general andadministrative expenses when insufficient Royalty income was received by theTrust, reducing the reserve amount held by the Trust to $1,199,813 as of March 31,2006. The reserve amount at March 31, 2005 was $1,409,920. Amounts will bewithheld to increase this reserve to its calculated balance when the Trustreceives Royalty income in future periods.

**Note 7—SubsequentEvents**

Based on pending capital projects and the anticipatedtiming of restoring production and revenues on various properties, it iscurrently expected that an additional deposit to the Trust’s Special CostEscrow will be required during the Trust’s second quarter of 2006 and that nodistributable income will be available for that period.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

**Critical AccountingPolicies**

The financial statements of the Trust are prepared onthe following basis:

(a)          Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter. In addition, Royalty incomeincludes amounts related to funds deposited or released from the Special CostEscrow account—see (c); and

(b)         Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses; and

(c)          The funds deposited orreleased from the Special Cost Escrow account are recorded at the time ofpayment or receipt. The Special Cost Escrow account is an account of theWorking Interest Owners and is not reflected in the financial statements of theTrust.

This manner of reporting income and expenses isconsidered to be the most meaningful because the quarterly distributions toUnit holders are based on net cash receipts received from the Working InterestOwners. The financial statements of the Trust differ from financial statementsprepared in accordance with generally accepted accounting principles, because,under such principles, Royalty income and Trust general and administrativeexpenses for a quarter would be recognized on an accrual basis. In addition,amortization of the net overriding royalty interest, calculated on aunits-of-production basis, is charged directly to Trust corpus since suchamount does not affect distributable income.

The Trustees, includingthe Corporate Trustee, have no authority over, have not evaluated and make nostatement concerning, the internal control over financial reporting of theworking interest owners.

**Financial Review**

**Three Months Ended March 31,2006 and 2005**

There were no distributions to the Unit holders forthe three months ended March 31, 2006 as compared to $316,435 or $.066597per Unit for the same period in 2005. The reason for no distributable incomefor the first quarter of 2006 was primarily as a result of damages caused tothe royalty properties by Hurricanes Rita and Katrina discussed below in“—Operational Review” and a required deposit to the Special Cost Escrowaccount.

Crude oil and condensate revenues decreased $2,733,769to $5,637,176 in the first quarter of 2006 as compared to $8,370,945  in the first quarter of 2005, due to damagescaused by Hurricanes Rita and Katrina. The average price of crude oil andcondensate increased from $44.58 per barrel in the first quarter of 2005 to$56.60 per barrel in the first quarter of 2006.

Gas revenues decreased $2,933,823, or 84%, to $560,132in the first quarter of 2006 from $3,493,955 in the first quarter of 2005, dueto a decrease in gas volumes of 83% to 84,153 Mcf in the first quarter of 2006from 493,708 Mcf in the first quarter of 2005, and by a $0.42 or 6% decrease inthe average price received for natural gas to $6.66 per Mcf in the firstquarter of 2006 from $7.08 per Mcf in the first quarter of 2005. Gas productsrevenue decreased $356,825, to $109,892 in the first quarter of 2006 from$466,717 in the first 

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quarter of 2005 dueprimarily to a decrease in production volume of 426,760 gallons to 141,784gallons from 568,544 gallons.

The Trust’s share of capital expenditures increased$454,853, from $1,272,714 in the first quarter of 2005 to $1,727,567 in thefirst quarter of 2006. The increase in capital expenditures for the firstquarter of 2006 related primarily to damages caused by Hurricanes Rita andKatrina.

The Trust did not have undistributed net income in thefirst quarter of 2006.

In the first quarter of 2006, there was a net depositof funds into the Special Cost Escrow account. The Trust’s share of the fundsdeposited was $876,000. The deposit was primarily a result of additional futureestimated abandonment costs and future capital expenditures. As of March 31,2006, $6,492,125 remained in the Special Cost Escrow account. The Special CostEscrow is set aside for estimated abandonment costs and future capitalexpenditures as provided for in the Conveyance. For additional informationrelating to the Special Cost Escrow see “Special Cost Escrow” account below.

In the first quarter of2005, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the funds deposited was $1,944,000.

**Reserve for FutureTrust Expenses**

In accordance with theprovisions of the Trust Agreement, generally all Royalty income received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. In the first quarter of 1998,the Trust determined that the Trust’s cash reserve was sufficient at that timeto provide for future administrative expenses in connection with the winding upof the Trust. The Trust determined that a cash reserve equal to three times theaverage expenses of the Trust during each of the past three years wassufficient at this time to provide for future administrative expenses inconnection with the winding up of the Trust. The reserve amount for 2006 wascalculated to be $1,504,904. During the first quarter of 2006, the Trust used$164,390 from the Trust’s cash reserve account to pay the Trust’s general andadministrative expenses when insufficient Royalty income was received by theTrust, reducing the reserve amount held by the Trust to $1,199,813 as of March 31,2006. The reserve amount for 2005 was $1,409,920. Amounts will be withheld toincrease this reserve to its calculated balance when the Trust receives Royaltyincome in future periods.

**Other**

The amount of cashdistributed by the Trust is dependent on, among other things, the sales pricesand quantities of oil and gas produced from the Royalty Properties. It shouldbe noted that substantial uncertainties exist with regard to future oil and gasprices, which are subject to material fluctuations due to changes in productionlevels and pricing and other actions taken by major petroleum producingnations, as well as the regional supply and demand for oil and gas, weather,industrial growth, conservation measures, competition and other variables.

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**Operational Review**

**Three Months Ended March 31, 2006 and 2005**

The following operationalinformation has been based on information provided to the Corporate Trustee byChevron as the Managing General Partner of the Partnership and by theapplicable Working Interest Owners. The Trustees have no control over theseoperations or internal controls relating to this information.

At the end of October2005, approximately half of Chevron oil-equivalent production in the Gulf ofMexico remained shut in due to damages from hurricanes in the third quarter.The time it will take to resume this production is uncertain, and some of thevolumes may not be sufficiently economic to restore. The impact to the Trustproperties is estimated to be a 68% reduction in production. Eugene Island 339remains shut-in, but production is currently expected to resume at the end of2006 after a new sales platform is built by the operator to replace the EugeneIsland 338 sales platform destroyed by Hurricane Rita, and assumingtransportation availability is fully restored on a third-party transmissionpipeline that incurred significant hurricane-related damages. The operator ofthis pipeline has advised that hurricane-related damages on their pipeline aremore extensive than previously thought, and the Working Interest Owner hasadvised the Trustee that it is currently evaluating various alternatives fortransportation as production is also restored. The Working Interest Owner hasalso advised the Trust that it is working on a project to compress andre-inject gas to the B-5 well, which would allow the operator to increase oilproduction and to limit flaring of gas. On Ship Shoal 182/183, gas productionremains shut-in due to the Tennessee Gas pipeline being down. Major repairs areexpected to be completed in late May and gas production on Ship Shoal 182/183is expected to resume in June of 2006. On West Cameron 643, production hasremained shut-in since September 2005 following Hurricane Rita’s major damageto various platforms, but repairs are close to completion and gas production onthis field is expected to resume in mid-2006.

*Volumes and dollar amounts discussed below representamounts recorded by the Working Interest Owners unless otherwise specified.*

Ship Shoal 182/183 crudeoil revenues increased from $4,251,634 in the first quarter of 2005 to$4,596,633 in the first quarter of 2006, partially offset by a decrease in netcrude oil production from 91,356 barrels in the first quarter of 2005 to 76,556barrels in the first quarter of 2006, which included an adjustment of 6,447barrels relating to the fourth quarter of 2005. The average crude oil priceincreased from $46.54 per barrel in the first quarter of 2005 to $60.04 perbarrel for the same period in 2006. Gas revenues decreased from $1,627,972 inthe first quarter of 2005 to $0 in the first quarter of 2006 due to damagescaused by Hurricanes Rita and Katrina that caused gas production to decreasefrom 230,289 Mcf in the first quarter of 2005 to 0 Mcf in the first quarter of2006. Capital expenditures increased from $657,885 in the first quarter of 2005to $718,062 in the first quarter of 2006 primarily due to repair and upgradework on the platforms associated with damages caused by Hurricanes Rita andKatrina. Operating expenses increased from $309,907 in the first quarter of2005 to $539,059 for the same period in 2006.

Eugene Island 339 netcrude oil revenues decreased from $3,995,299 in the first quarter of 2005 to$941,690 for the same period in 2006 due to a decrease in volumes to 21,299barrels from 93,732 barrels in 

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thefirst quarter of 2005. In addition, the average crude oil price increased from$42.62 per barrel in the first quarter of 2005 to $44.21 per barrel in thefirst quarter of 2006. Gas revenues decreased from $1,519,141 in the firstquarter 2005 to $547,819 in the first quarter of 2006 primarily due to adecrease in natural gas volumes from 211,558 Mcf in the first quarter of 2005to 83,101 Mcf in the first quarter of 2006. Capital expenditures increased from$589,057 in the first quarter of 2005 to $962,783 in the first quarter of 2006due to repair and upgrade work on the platforms associated with damages causedby Hurricanes Rita and Katrina. Operating expenses decreased from $337,108 inthe first quarter of 2005 to $206,737 in the first quarter of 2006.

West Cameron 643 gasrevenues decreased from $296,606 in the first quarter of 2005 to $0 in thefirst quarter of 2006. This is due to a decrease in gas volumes from 44,773 Mcfin the first quarter of 2005 to 0 Mcf for the same period in 2006.Operating expenses increased from $154,926 in the first quarter of 2005 to$169,016 for the same period in 2006, and capital expenditures increased from$1,034 in the first quarter of 2005 to $46,155 for the same period in 2006.

East Cameron 371/381 crudeoil revenues decreased from $1,005 in the first quarter of 2005 to $0 in thefirst quarter of 2006 primarily due to the decrease in crude oil productionfrom 22 barrels in the first quarter of 2005 to 0 barrels for the same periodin 2006. Gas revenues decreased from $10,770 in the first quarter of 2005 to $0in the first quarter of 2006. This is due to a decrease in gas volumes from1,476 Mcf in the first quarter of 2005 to 0 Mcf for the same period in 2006. Operatingexpenses decreased from $12,012 in the first quarter of 2005 to $4,033 in thefirst quarter of 2006.

**Future Net Revenues and Termination of the Trust**

Based on a reserve studyprovided to the Trust by DeGolyer and MacNaughton, independent petroleum engineers,as of October 31, 2005 future net revenues attributable to the Trust’sroyalty interests were estimated at $48.0 million. Estimates of proved oiland gas reserves attributable to the Partnership’s royalty interest are basedon existing economic and operating conditions in effect at October 31,2005 in order to correspond to with distributions to the Trust. Such reservestudy also indicates that approximately 71% of the future net revenues from theRoyalty Properties are expected to be received by the Trust during the nextthree years. In addition, because the Trust will terminate in the eventestimated future net revenues fall below $2.0 million, it would bepossible for the Trust to terminate even though some or all of the RoyaltyProperties continued to have remaining productive lives. Upon termination ofthe Trust, the Trustees will sell for cash all of the assets held in the Trustestate and make a final distribution to Unit holders of any funds remainingafter all Trust liabilities have been satisfied. The estimates of future netrevenues discussed above are subject to large variances from year to year andshould not be construed as exact. There are numerous uncertainties present inestimating future net revenues for the Royalty Properties. The estimate mayvary depending on changes in market prices for crude oil and natural gas, therecoverable reserves, annual production and costs assumed by DeGolyer andMacNaughton. In addition, future economic and operating conditions as well asresults of future drilling plans may cause significant changes in suchestimate. The discussion set forth above is qualified in its entirety byreference to the Trust’s 2005 Annual Report on Form 10-K. The Trust’sForm 10-K is available at the SEC’s website at *www.sec.gov*or upon request from the Corporate Trustee.

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**Special Cost Escrow Account**

The Conveyance providesfor reserving funds for estimated future “Special Costs” of plugging andabandoning wells, dismantling platforms and other costs of abandoning theRoyalty Properties, as well as for the estimated amount of future drillingprojects and other capital expenditures on the Royalty Properties. As providedin the Conveyance, the amount of funds to be reserved is determined based onfactors including estimates of aggregate future production costs, aggregatefuture Special Costs, aggregate future net revenues and actual current netproceeds. Deposits into this account reduce current distributions and areplaced in an escrow account and invested in short-term certificates of deposit.Such account is herein referred to as the “Special Cost Escrow” account. TheTrust’s share of interest generated from the Special Cost Escrow account servesto reduce the Trust’s share of allocated production costs. Special Cost Escrowfunds will generally be utilized to pay Special Costs to the extent there arenot adequate current net proceeds to pay such costs. Special Costs that havebeen paid are no longer included in the Special Cost Escrow calculation.Deposits to the Special Cost Escrow account will generally be made when thebalance in the Special Cost Escrow account is less than 125% of estimatedfuture Special Costs and there is a Net Revenues Shortfall (a calculation ofthe excess of estimated future costs over estimated future net revenuespursuant to a formula contained in the Conveyance). When there is not a NetRevenues Shortfall, amounts in the Special Cost Escrow account will generallybe released, to the extent that Special Costs have been incurred. Amounts inthe Special Cost Escrow account generally will also be released when thebalance in such account exceeds 125% of estimated future Special Costs. In thefirst quarter of 2006, there was a net deposit of funds to the Special CostEscrow account of $876,000. The deposit was primarily a result of additionalfuture estimated abandonment costs and future capital expenditures.

As of March 31, 2006,$6,492,125 remained in the Special Cost Escrow account.

Chevron, in its capacityas Managing General Partner of the Partnership, has advised the Trust thatadditional deposits to the Special Cost Escrow account may be required infuture periods in connection with other production costs, other abandonmentcosts, other capital expenditures and changes in the estimates and factorsdescribed above. Such deposits could result in a significant reduction inRoyalty income in the periods in which such deposits are made, including thepossibility that no Royalty income would be received in such periods.

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**Overview ofProduction, Prices and Royalty Income**

Thefollowing schedule provides a summary of the volumes and weighted averageprices for crude oil and condensate and natural gas recorded by the WorkingInterest Owners for the Royalty Properties, as well as the Working InterestOwners’ calculations of the net proceeds and the royalties paid to the Trustduring the periods indicated. Net proceeds due to the Trust are calculated foreach three month period commencing on the first day of February, May, August andNovember.

| ** **                                                   | ** ** | **Royalty Properties**      | ** ** |
|--------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                   | ** ** | **Three Months Ended** | ** ** |
| ** **                                                   | ** ** | **March 31,(1)**            | ** ** |
| ** **                                                   | ** ** | **2006**                         | ** ** | **2005** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 99,608                           |       | 187,778 |   |
| Natural gas and  gas products (Mcfe)                         |       | 104,408                          |       | 574,929 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                | 56.60      |   | $ | 44.58 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                | 6.66       |   | $ | 7.08 |   |
| Crude oil and  condensate revenues                           |       | $                                | 5,637,176  |   | $ | 8,370,945 |   |
| Natural gas and  gas products revenues                       |       | 670,025                          |       | 3,960,672 |   |
| Production  expenses                                         |       | (1,208,736                       | )          | (1,259,653 | ) |
| Capital  expenditures                                        |       | (1,727,567                       | )          | (1,272,714 | ) |
| Undistributed net  income(2)                                 |       | —                           |       | — |   |
| Refund of  (provision for) Special Cost Escrow               |       | (3,370,898                       | )          | (7,691,152 | ) |
| **Net  Proceeds**                                            |       | —                           |       | 2,108,098 |   |
| Royalty interest                                             |       | x25                              | %          | x25 | % |
| Partnership share                                            |       | —                           |       | 527,025 |   |
| Trust interest                                               |       | x99.99                           | %          | x99.99 | % |
| Trust share of Royalty  income                               |       | $                                | —     |   | $ | 526,972 |   |

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(1)          Amounts represent actualproduction for the three month period ended January of each year,respectively.

(2)          Undistributednet loss represents negative net proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive net proceeds earned by the related Working InterestOwner(s). Undistributed net income represents positive net proceeds, generatedduring the respective period, that were applied to an existing losscaryforward. As of March 31, 2006, the loss carryforward was $0.

**Item 3.**                        Quantitativeand Qualitative Disclosure About Market Risk

No material changes haveoccurred since our Annual Report on Form 10-K for the year-ended December 31,2005. Reference is also made to Note 2 of the Notes to FinancialStatements included in Item 1 of this Form 10-Q.

**Item 4.**                        Controlsand Procedures.

*Evaluationof disclosure controls and procedures.**  *The Corporate Trustee maintainsdisclosure controls and procedures designed to ensure that information requiredto be disclosed by the Trust in the 

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reports that it files orsubmits under the Exchange Act of 1934, as amended, is recorded, processed,summarized and reported within the time periods specified in the SEC’s rules andregulations. Disclosure controls and procedures include controls and proceduresdesigned to ensure that information required to be disclosed by the Trust isaccumulated and communicated by Chevron, as the managing general partner of thePartnership, and the working interest owners to JPMorgan Chase Bank, N.A., asCorporate Trustee of the Trust, and its employees who participate in thepreparation of the Trust’s periodic reports as appropriate to allow timelydecisions regarding required disclosure.

As of the end of the period covered by this report,the Corporate Trustee carried out an evaluation of the Trust’s disclosurecontrols and procedures. Mike Ulrich, as Trust Officer of the CorporateTrustee, has concluded that the disclosure controls and procedures of the Trustare effective.

Due to the contractual arrangements of (i) theTrust Agreement, (ii) the Partnership Agreement and (iii) the rightsof the Partnership under the Conveyance regarding information furnished by theworking interest owners, the Trustees rely on (A) information provided bythe Working Interest Owners, including historical operating data, plans forfuture operating and capital expenditures, reserve information and informationrelating to projected production. (B) information from the managinggeneral partner of the Partnership, including information that is collectedfrom the Working Interest Owners, and (C) conclusions and reports regarding reserves bythe Trust’s independent reserve engineers. See Item 1A. Risk Factors “—Noneof the Trustees, the Trust nor its Unit holders control the operation ordevelopment of the Royalty Properties and have litte influence over operationor development” in the Trust’s Form 10-K for the year endedDecember 31, 2005, and “Note 5—Negative Adjustments” of the financialstatements and “Management’s Discussion and Analysis of Financial Condition andResults of Operating” relating to operating information on East Cameron 371/381included in the Annual Report on Form 10-K for the year ended December 31,2005 for a description of certain risks relating to these arrangements andreliance and applicable adjustments to operating information when reported bythe Working Interest Owners to the Corporate Trustee and recorded in the Trust’sresults of operation.

*Changes in InternalControl Over Financial Reporting.**  *During the three months ended March 31,2006, there has been no change in the Corporate Trustee’s internal control overfinancial reporting that has materially affected, or is reasonably likely tomaterially affect, the Corporate Trustee’s internal control over financialreporting relating to the Trust. The Corporate Trustee notes for purposes ofclarification that it has no authority over, and makes no statement concerning,the internal control over financial reporting of the Working Interest Owners orthe managing general partner of the Partnership.

**Item 1A.**                RiskFactors.

There have not been any material changes from riskfactors previously disclosed in the Trust’s Form 10-K in response toItem 1A of Part 1 of its Form 10-K for the year ended December 31,2005.

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**PART II—OTHERINFORMATION**

**Item 6.**                        Exhibits.

(Asterisk indicates exhibit previously filed with theSecurities and Exchange Commission and incorporated herein by reference.)

|        | ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                           | ** ** | **SEC File or  Registration  Number** | ** ** | **Exhibit  Number** |
|--------|------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|---------------------|
| 4(a)*  |       | —     | Trust Agreement dated as  of January 1, 1983, among Tenneco Offshore Company, Inc., Texas  Commerce Bank National Association, as corporate trustee, and Horace C.  Bailey, Joseph C. Broadus and F. Arnold Daum, as individual trustees  (Exhibit 4(a) to Form 10-K for the year ended  December 31, 1992 of TEL Offshore Trust) |       | 0-6910                                |       | 4(a)                |
| 4(b)*  |       | —     | Agreement of General  Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and  the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to  Form 10-K for year ended December 31, 1992 of TEL Offshore  Trust)                                                                                                     |       | 0-6910                                |       | 4(b)                |
| 4(c)*  |       | —     | Conveyance of Overriding  Royalty Interests from Exploration I to the Partnership  (Exhibit 4(c) to Form 10-K for year ended  December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                           |       | 0-6910                                |       | 4(c)                |
| 4(d)*  |       | —     | Amendments to TEL  Offshore Trust Agreement, dated December 7, 1984  (Exhibit 4(d) to Form 10-K for year ended  December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                                    |       | 0-6910                                |       | 4(d)                |
| 4(e)*  |       | —     | Amendment to the  Agreement of General Partnership of TEL Offshore Trust Partnership, effective  Offshore Trust)                                                                                                                                                                                                                                                     |       | 0-6910                                |       | 4(e)                |
| 10(a)* |       | —     | Purchase Agreement,  dated as of December 7, 1984 by and between Tenneco Oil Company and  Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K  for year ended December 31, 1992, of TEL Offshore Trust)                                                                                                                                 |       | 0-6910                                |       | 10(a)               |
| 10(b)* |       | —     | Consent Agreement, dated  November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company  (Exhibit 10(b) to Form 10-K for year ended  December 31, 1988 of TEL Offshore Trust)                                                                                                                                                       |       | 0-6910                                |       | 10(b)               |
| 10(c)* |       | —     | Assignment and  Assumption Agreement, dated November 17, 1988, between Tenneco Oil  Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to  Form 10-K for year ended December 31, 1988 of TEL Offshore  Trust)                                                                                                                               |       | 0-6910                                |       | 10(c)               |
| 10(d)* |       | —     | Gas Purchase and Sales  Agreement Effective September 1, 1993 between Tennessee Gas Pipeline  Company and Chevron U.S.A. Production Company (Exhibit 10(d) to  Form 10-K for year ended December 31, 1993 of TEL Offshore  Trust)                                                                                                           |       | 0-6910                                |       | 10(d)               |
| 31     |       | —     | Certification furnished  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                              |       |                                  |       |                |
| 32     |       | —     | Certification furnished  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                              |       |                                  |       |                |

 

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized.

|            | TEL OFFSHORE TRUST |
|------------|--------------------|
|       | By:                |   | JPMorgan Chase Bank, N.  A. Corporate Trustee |
|       | By:                | ** ** | /s/  MIKE ULRICH |
| ** ** | ** **         | ** ** | **Mike  Ulrich*Vice President*** |

 

**Date: May 15, 2006**

The Registrant, TEL Offshore Trust, has no principalexecutive officer, principal financial officer, board of directors or personsperforming similar functions. Accordingly, no additional signatures areavailable and none have been provided.

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